1. Technical Field of the Invention
The present invention generally relates to sulfur recovery processes and apparatus for removing hydrogen sulfide from waste gas. More particularly, the invention relates to such processes that avoid thermally combusting H2S and to apparatus that does not include a conventional Claus thermal reactor.
2. Description of the Related Art
In many industrial situations today it is desirable to prepare elemental sulfur from H2S or gaseous mixtures containing moderate to high concentrations of H2S. Often this is done in conjunction with cleaning up gaseous petroleum feed streams that contain H2S, since sulfur is generally considered undesirable in most petroleum refining products and the quality of the various petroleum fractions may be upgraded by removing the sulfur content. For example, a natural gas stream containing H2S is treated to remove the H2S, and the H2S rich gas fed to a modified Claus sulfur recovery unit which converts the H2S to elemental sulfur. In the modified Claus process, hydrogen sulfide is partially combusted with air in a reaction furnace to form sulfur dioxide. The combustion gases are cooled in a waste heat boiler in which a portion of the uncombusted hydrogen sulfide reacts with sulfur dioxide to form elemental sulfur and water vapor. The partially converted mixture then flows to a condenser where the elemental sulfur is removed in molten form. The remaining gases are then heated and passed over a catalytic converter bed for further conversion to elemental sulfur and then again cooled to condense incremental sulfur. From one to four stages of reheat, conversion and condensing are typically used. FIG. 1 is a flow diagram of a typical prior art Claus plant. A coalescer is sometimes provided to remove entrained liquids (sulfur) from the final condenser tail gas. In many cases, a xe2x80x9ctail gasxe2x80x9d cleanup unit such as the well-known SCOT unit is utilized to clean up the tail gas from the modified Claus process. Tail gas treatment units process the unreacted H2S, SO2, various compounds such as COS and CS2, and elemental sulfur vapor into H2S which is then recycled back to the thermal stage of the Claus process. Alternatively, the remaining sulfur containing compounds are converted to SO2 which is absorbed in aqueous solutions to form bisulfite salts. Still other types of tail gas treatments which have been well described in the literature involve operating Claus catalyst beds at temperatures below the dew point of sulfur, or promote the direct oxidation of the remaining H2S to sulfur over a bed of solid catalyst or in a liquid contacting device. The waste gas emerging from the tail gas unit is typically vented into the atmosphere after incineration of the residual sulfur containing compounds to SO2. The thermal stage of the Claus process is a burner in a refractory lined chamber. H2S along with other compounds such as CO2, methane and light hydrocarbon gases, nitrogen, ammonia, and hydrogen, is fed to the burner. Air, pure oxygen, or a mixture of both is also fed to the burner. A flame is used to ignite the mixture of gases. In the flame, ⅓ of the H2 S is oxidized by the reaction:
H2S+{fraction (3/2)}O2xe2x86x92SO2+H2Oxe2x80x83xe2x80x83(1) 
The remaining ⅔ of the H2S then reacts with the SO2 generated in the flame to form elemental sulfur and water:
2H2S+SO2⇄3/xSx+2H2Oxe2x80x83xe2x80x83(2) 
wherein x=2, 6, or 8. Together, reaction stages (1) and (2) are referred to as the xe2x80x9cClaus reaction.xe2x80x9d The maximum efficiency for conversion to sulfur is given by equilibrium computations best described by Gamson and Elkins (Chem. Eng. Prog. (1953) 4 9:203-215) to be 70 to 75%, depending on the flame temperature. The efficiency decreases with decreasing residence time in the reactor. The sulfur formed by the thermal stage is recovered as a liquid by first cooling the hot reaction gases (typically about 1,800-2,700xc2x0 F.) in a fire tube boiler, followed by condensation in the tubes of a low pressure steam generator. Removing the liquid sulfur allows the equilibrium Claus reaction in reaction (2), above, to shift to the right to form more sulfur. At low temperatures (i.e., below 500xc2x0 F.) sulfur formation from the Claus reaction is about 90 to 98% efficient, but requires a catalyst to make the reaction go at an acceptable rate. The gas containing the unreacted H2S and SO2, in the 2:1 ratio required for the Claus reaction, are heated to a temperature which prevents liquid sulfur from condensing in the catalyst bed by varying means. The gas passes over the catalyst and the Claus reaction proceeds until equilibrium is reached. Reactor effluent is cooled and sulfur is again condensed out of the gas stream. The reheat of the gases, catalytic reaction, and sulfur condensation is repeated. Usually, 2 to 3 catalytic stages are employed. Any remaining H2S, SO2, sulfur, or other sulfur compounds in the Claus plant effluent are either incinerated to SO2 and discharged to the atmosphere, or incinerated to SO2 and absorbed by chemical reaction, or converted by hydrogen to H2S and recycled or absorbed by an alkanolamine solution. This is accomplished by various Claus xe2x80x9ctail gasxe2x80x9d treatment units, which improve the efficiency of sulfur removal from the gas discharged to the atmosphere.
Over several decades, there have been modifications of the Claus process, mainly involving improvement of the burner design, more active and durable catalysts, different types of reheaters, and in some cases replacing air with oxygen as the oxidizer. Some of the more recent improvements have been directed toward significantly increasing the processing capability of the process. (Watson, et. al., xe2x80x9cThe Successful Use of Oxygen in Claus Plants,xe2x80x9d HTI Quarterly: Winter 1995/1996 pp. 95-101) The basic H2S conversion process remains essentially the same, however, since its inception in 1883.
The greatest problem with the Claus process is the inherent equilibrium constraint of the Claus reaction caused by the necessity of generating the SO2 intermediate. Others have addressed this problem by attempting to directly oxidize H2S to sulfur using alumina based catalysts and low temperature operating conditions. Typically, these processes are catalytic oxidations operating at temperatures below about 454xc2x0 C., so that the reaction can be contained in ordinary carbon steel vessels. Usually these catalytic oxidation processes are limited to Claus tail gas operations or sulfur recovery from streams that have very low H2S content (i.e., about 1-3%). One reason for this limited use is that the heat evolved from the oxidation of a concentrated stream of H2S would drive the reaction temperatures well above 454xc2x0 C. requiring refractory lined vessels such as the conventional Claus thermal reactor. Low concentration H2S streams will not produce enough energy release from oxidation to sustain a flame as in a thermal reactor stage. These existing catalytic oxidation technologies are therefore limited to low concentration streams using non-refractory lined vessels. These processes are also limited in the amount of sulfur that can be handled because the heat transfer equipment needed to remove the heat of reaction becomes extremely large due to the low temperature differential between the process and the coolant streams.
Other techniques for improving efficiency of sulfur removal that have been described in the literature include: 1) adsorbing sulfur cooled below the freezing point on a solid material followed by releasing the trapped sulfur as a liquid by heating the solid adsorbent; 2) selectively oxidizing the remaining H2S to sulfur using air; and 3) selectively oxidizing the H2S to sulfur employing aqueous redox chemistry utilizing chelated iron salts or nitrite salts in an attempt to purifying hydrogen sulfide contaminated hydrogen or gaseous light hydrocarbon resources. According to these methods, the H2S-contaminated hydrogen or hydrocarbon stream is contacted directly with the redox reagent such as chelated iron (III) ions. The iron (III) is reduced to iron (II) ion while the H2S is converted to elemental sulfur. The sulfur in liquid form is separated from the solution. These types of desulfurization units have been proven to be practical when the amount of sulfur to be removed from the stream is below 5 long tons per day. The Sulfurox(trademark) and Lo-Cat(trademark) processes are examples of this type of H2S conversion process. Some of these direct oxidation processes use a liquid media to carry out the oxidation or to act as a carrier for the oxidizer. These processes are also limited in the amount of sulfur recovered due to the heat removal constraints at low temperatures and the need to maintain low temperatures to keep the liquid from boiling. For these reasons, existing direct oxidation processes have not proved to be viable substitutes for the Claus process in most industrial applications.
U.S. Pat. Nos. 5,700,440; 5,807,410 and 5,897,850 describe some of the limitations of existing tail gas treatment (TGT) processes and the difficulty of meeting increasingly stringent government requirements for desulfurization efficiency in the industry. J. B. Hyne (Oil and Gas Journal Aug. 28, 1972: 64:78) gives an overview of available processes for effluent gas stream desulfurization and discusses economical and environmental considerations. R. H. Hass et al. (Hydrocarbon Processing May 1981:104-107) describe the BSR/Selectox(trademark) process for conversion of residual sulfur in Claus tail gas or for pre-Claus treatment of a gas stream. K-T Li at al. (Ind. Eng. Chem. Res. 36:1480-1484 (1997)) describe the SuperClaus(trademark) TGT system which uses vanadium antimonate catalysts to catalyze the selective oxidation of hydrogen sulfide to elemental sulfur. U.S. Pat. No. 5,603,913 describes several oxide catalysts that have been suggested for catalyzing the reaction
H2S+xc2xdO2xe2x86x92xc2xdS2+H2Oxe2x80x83xe2x80x83(4) 
Because reaction (4) is not a thermodynamically reversible reaction, direct oxidation techniques offer potentially higher levels of conversion than is typically obtainable with thermal and catalytic oxidation of H2S. Most direct oxidation methods are applicable to sour gas streams containing relatively small amounts of H2S and large amounts of hydrocarbons, but are not particularly well suited for handling the more concentrated acid gas streams from refineries. For this reason direct oxidation methods have been generally limited to use as tail gas treatments only, and have not found general industrial applicability for first stage sulfur removal systems from gases containing large quantities of H2S.
Z. R. Ismagilov et al. (React. Kinet. Catal. Lett. 55:489-499 (1995)) suggest that monolith catalysts containing oxides of Co, V, Fe, Cr, Mn or Al have activity for catalytically converting the H2S in natural gas to sulfur in a first oxidation stage. The reaction conditions include a spherical particulate vanadium catalyst in a fluid bed reactor operating at 250-300xc2x0 C., O2:H2S =0.5-1.1 and tc=0.5-0.8 s. Under such conditions H2S conversion and process selectivity of 99% is reported.
U.S. Pat. No. 4,886,649 (Ismagilov, et al.) describes a two stage direct oxidation process employing fluidized catalyst beds containing MgCrO4 and Al2O3, or V2O5 and Al2O3. According to that method, oxygen is supplied to the first oxidation stage in an amount of 100-110% of the stoichiometric amount necessary for oxidation of H2S to elemental sulfur. The range of treatable H2S containing gases is extended to gases containing about 30-50 vol. % H2S. The granular catalyst in a fluidized bed with a cooling coil or jacket, allows temperature uniformity of the catalyst bed. A maximum temperature level of 250-350xc2x0 C. is desired in order to avoid forming products of coking and cracking of hydrocarbon components of the feed gas.
In an unrelated area of endeavor, various carbided metal catalysts have been prepared, some of which have been used for catalyzing the oxidative conversion of methane to synthesis gas. For example, Claridge et al. (J. Catalysis 180:85-100 (1998)) have described high-surface-area molybdenum carbide catalysts and tungsten carbide catalysts for conversion of methane to synthesis gas via steam reforming, dry reforming or partial oxidation processes. Maintaining elevated pressure during the conversion process stabilized the carbide and deterred catalyst deactivation.
U.S. Pat. No. 4,325,843 (Slaugh et al.) describes a process for making a supported tungsten carbide composition for use as a catalyst. The process includes impregnating an oxidic support material with a solution of a tungsten salt, converting the tungsten to a nitride and treating the supported tungsten nitride with a carbiding gas mixture.
U.S. Pat. No. 4,325,842 (Slaugh et al.) describes a process for preparing a supported molybdenum carbide catalyst by impregnating a porous support with a solution of hexamolybdenum dodecachloride, drying, and heating in a carbiding atmosphere. U.S. Pat. No. 4,326,992 (Slaugh et al.) describes another process for preparing a supported molybdenum carbide catalyst. In this process an ammonium hydroxide solution of molybdic acid is applied to a porous support, dried and heated in a carbiding atmosphere. U.S. Pat. No. 5,338,716 (Triplett et al.) discloses a supported non-oxide metal carbide-containing catalyst that includes an oxide support, a passivating layer, and a non-oxide metal ceramic catalytic component such as tungsten carbide or molybdenum carbide, or another Group VI metal carbide or nitride.
U.S. Pat. Nos. 5,451,557 and 5,573,991 (Sherif) disclose other processes for forming a metal carbide catalyst such as tungsten carbide or another Group VIB transition metal carbide. U.S. Pat. No. 4,331,544 (Takaya et al.) describes a catalyst for catalyzing the synthesis of methane from CO and H2. That catalyst comprises a nickel-molybdenum alloy and a molybdenum carbide supported on a porous carrier. Still other metal carbide catalysts are disclosed in U.S. Pat. No. 4,219,445 (Finch), U.S. Pat. No. 1,930,716 (Jaeger), and U.S. Pat. No. 4,271,041 (Boudart et al.). Carbided catalysts do not appear to have not been previously employed in sulfur recovery processes.
Even though the Claus process still finds widespread industrial use today for recovering elemental sulfur from H2S that is generated in many industrial processes, such as petroleum refinery processes, and for reducing sulfur emissions from refineries, the Claus process is generally viewed as relatively costly for routine use on a commercial scale. As a result, the Claus process is currently performed mainly for the purpose of complying with government mandated environmental air quality standards. Most of the existing alternative desulfurization processes and systems must resort to use of additional pre-treatments or post-treatment catalytic stages and tail gas treatments in order to adequately clean the waste gas that is vented into the air. A more economical and efficient way of recovering elemental sulfur from an H2S-containing gas stream and of removing environmentally harmful H2S from gas well emissions and from industrial vent stack exhaust gases is needed.
The present invention overcomes major deficiencies of the prior art by providing a process and apparatus in which higher concentrations of H2S can be directly oxidized to elemental sulfur and water than was previously possible with known methods, catalysts and apparatus. This is accomplished without employing a flame to produce an SO2 intermediate. In many cases the yield of recovered elemental sulfur is also enhanced compared to that of conventional Claus recovery processes and apparatus or existing direct oxidation processes such as Selectox(trademark) and SuperClaus(trademark), which are typically employed for Claus tail gas treatment today. This offers profound advantages for reducing pollution of the air by H2S escaping from natural gas wells and from petroleum refinery vent stacks. Another advantage of the present apparatus and process is that they can be operated at superatmospheric pressures, which makes possible for the first time a compact sulfur removal plant. The new apparatus and improved process also make it more economically and environmentally feasible for refineries to utilize high sulfur crude oils by providing for the efficient recovery of the accompanying H2S waste gas. Employing a short contact time reactor and a suitable catalyst such as Pt, Rh, or Ptxe2x80x94Rh, the process allows the direct oxidation of H2S to take place on gas streams containing a much wider range of H2S concentrations than is presently possible with conventional H2S direct oxidation processes and operating at temperatures ranging up to about 1,500xc2x0 C. By eliminating SO2 formation, the equilibrium constraint of the Claus reaction (2) is removed and the conversion of H2S to sulfur in the direct oxidation step is urged forward toward completion. Achieving a high level of conversion in the initial direct oxidation stage (1) allows the elimination of the intermediate catalytic stages of the Claus reaction. The avoidance of substantial SO2 formation also eliminates the need for SO2 conversion or absorption from the tail gas of the present invention, a considerable improvement in operability and stability. The optimal operation of a conventional Claus sulfur removal unit is dependent on the air or air/oxygen supplied to the reaction. The optimum recovery is obtained when the gas leaving the Claus unit has an H2S to SO2 ratio of 2:1. This requires constant manipulation of the air fed to the plant.
By contrast, with the presently disclosed process and apparatus, which substantially avoid making SO2, the recovery is less dependent on fine manipulation of the air or air/oxygen to the reaction. Stability is gained by not having to rely as extensively on analyzers and controls to fine tune the amount of oxidizing gas.
In accordance with one aspect of the present invention, a gas desulfurization assembly for recovering H2S from a waste gas stream is provided. The assembly comprises a short contact time catalytic reactor having a H2S-containing gas injection inlet, an O2-containing gas injection inlet, a gas mixing zone, and a reaction zone comprising at least one catalyst device having activity for catalyzing the partial oxidation of H2S to elemental sulfur and water under reaction promoting conditions. The assembly also includes a cooling zone and a sulfur condenser in fluid communication with the cooling zone. The condenser has a liquid sulfur outlet and a desulfurized gas outlet. The injection inlets are in fluid communication with the gas mixing zone, the mixing zone is in fluid communication with the reaction zone, and the reaction zone is in fluid communication with the cooling zone. In some embodiments, the assembly also includes at least one tail gas treatment unit downstream from the sulfur condenser, with a heater placed in between for reheating the process gases before entering the tail gas treatment unit. In preferred embodiments, the reactor is capable of withstanding temperatures in the operating range of the H2S catalytic partial oxidation reaction, or at least 700xc2x0 C., preferably up to 1,500xc2x0 C. A thermal insulator is placed between the mixing zone and the reaction zone to deter excessive heating of the reactant gases prior to contacting the catalytic surfaces. In certain embodiments the cooling zone includes several or many thermally conductive tubes that run through a heat exchanger, to facilitate rapid cooling of the reacted gases. In preferred embodiments the cooling zone also includes at least one thermal insulator between the reaction zone and the thermally conductive tubes. These insulators a preferably a plurality of refractory ferrules each of which is attached to a thermally conductive tube. In some embodiments the cooling zone includes a heat exchanger, and the thermally conductive tubes extend there through.
In accordance with another aspect of the invention, a waste gas desulfurization process is provided. In preferred embodiments the process comprises providing a H2S-containing waste gas stream and a O2-containing stream to a millisecond contact time reactor. In certain embodiments the H2S-containing gas includes at least about 1 vol. % H2S, and in some embodiments the H2S-containing waste gas stream is almost entirely H2S. The O2-containing gas is chosen may be purified O2, air or O2 enriched air. The reactor has a gas mixing zone, a reaction zone capable of withstanding temperatures of at least about 700xc2x0 C., preferably up to at least 1,500xc2x0 C., and a cooling zone. The process further includes mixing together the H2S-containing gas stream and said O2-containing gas stream in the mixing zone to form a reactant gas mixture having a molar ratio of H2S to O2 of about 2:1 or less, the reaction zone containing a catalyst device having activity for catalyzing the partial oxidation of H2S to elemental sulfur and water under reaction promoting conditions. In certain embodiments the process includes preheating the H2S and O2 streams up to about 200xc2x0 C. Preferably the temperature of the mixing zone does not exceed about 200xc2x0 C. The process also includes maintaining the temperature of the reaction zone between about 700xc2x0 C.-1,500xc2x0 C., preferably in the range of 850xc2x0 C.-1,300xc2x0 C., and passing the reactant gas mixture over the catalyst device such that the contact time between the catalyst device and a portion of reactant gas mixture that contacts the catalyst device is no more than about 200 milliseconds, preferably under 50 milliseconds, and more preferably less than 20 milliseconds. Less than 10 millisecond contact time is highly preferred. The reaction H2S+xc2xdO2xe2x86x921/x Sx+H2O (x=2, 6 or 8) occurs and a product stream is formed that contains gaseous elemental sulfur and water. In some embodiments a substantially desulfurized residual waste gas is also present in the reacted or process gas stream. The process further includes passing the process gas stream into the cooling zone and cooling said product stream to a temperature above the dewpoint of sulfur, to provide a partially cooled product stream. The process still further includes passing the partially cooled product stream to a sulfur condenser and cooling the product stream to the dewpoint temperature of elemental sulfur, or lower, to allow recovery of elemental sulfur from the condenser. In some embodiments the process also includes venting the substantially desulfurized waste gas into the atmosphere, or otherwise disposing of the desulfurized waste gas.
In certain embodiments the desired temperature is maintained by regulating the reactor inlet temperature, the H2S concentration in the reactant gas mixture and/or by externally applying heat to the catalyst device, or a combination of those actions. Certain preferred embodiments include maintaining autothermal reaction promoting conditions. The term xe2x80x9cautothermalxe2x80x9d means that substantially no externally supplied heat must be provided to the catalyst in order to sustain the exothermic sulfur catalytic partial oxidation reaction and the H2S partial oxidation process. The term xe2x80x9cSCPOX,xe2x80x9d as used in this disclosure means xe2x80x9csulfur catalytic partial oxidation,xe2x80x9d and the term xe2x80x9cCPOXxe2x80x9d refers to the xe2x80x9ccatalytic partial oxidation of hydrocarbons.xe2x80x9d
In preferred embodiments, the catalyst device employed in the process comprises a metal having activity for catalyzing the reaction H2S+xc2xdO2xe2x86x921/x Sx+H2O, wherein x=2, 6 or 8, under reaction promoting conditions. Ensuring reaction promoting conditions may include adjusting the relative amounts of H2S, O2 and other oxidizable components (e.g., hydrocarbon) in the feed gas mixture. For example, an amount of O2 in excess of the stoichiometric amount of Reaction (4) is preferably provided if hydrocarbons are also present in the feed which are oxidizable over the chosen catalyst. Reaction promoting conditions may also include adjusting the amount of preheating of the reactant gas mixture and/or the catalyst, adjusting the operating pressure of the reactor, which is preferably maintained above atmospheric pressure, more preferably in excess of two atmospheres pressure. Increasing or decreasing the space velocity of the feed gas mixture, which is influenced not only by pressure but also by the configuration of the catalyst bed, its porosity and the associated pressure drop, also can be used to favor the H2S partial oxidation reaction.
In some embodiments the catalyst device contains a reduced metal such as platinum, rhodium, ruthenium, nickel, palladium, iridium, or a mixture of any of those metals. In some embodiments the catalyst also contains a lanthanide metal or metal oxide, and in certain embodiments the catalyst device comprises a porous refractory catalyst support made of a material such as Al2O3, ZrO2 or partially stabilized (MgO) zirconia (PSZ). In certain embodiments the catalyst device comprises one or more layers of wire gauze. In some embodiments, the catalyst device comprises a monolith or a packed bed of discrete or divided units or structures, such as regularly or irregularly shaped particles, granules, beads, pills, pellets, cylinders, trilobes, extrudates or spheres. With any of those forms of supported catalyst, a preferred catalytic metal is Pt, Rh, more preferably a Pt-Rh mixture. In some embodiments the catalyst device contains a Ptxe2x80x94Rh alloy supported on a lanthanide, preferably samarium, coated refractory support. In some embodiments, the catalyst device contains a carbided metal, preferably a Ptxe2x80x94Rh mixture.
In some embodiments the process comprises operating the reactor at a space velocity of at least about 100,000 hrxe2x88x921. In preferred embodiments the reactor is operated at superatmospheric pressure. These and other embodiments, features and advantages of the present invention will become apparent with reference to the following description and drawings.